Reservoir characterization and asset management use comprehensive information about formation fluids. This information is typically obtained at all stages of the exploration and development cycle for economic evaluation, field planning, and reservoir operation. In most hydrocarbon reservoirs, fluid composition varies vertically and laterally in a formation. Fluids may exhibit gradual changes in composition caused by gravity or biodegradation, or they may exhibit more abrupt changes due to structural or stratigraphic compartmentalization. Traditionally, fluid information has been obtained by capturing samples, either at downhole or surface conditions, and then measuring the pressure/volume/temperature (PVT) properties in a surface laboratory. In recent years, downhole fluid analysis (DFA) techniques, including contamination monitoring, composition measurement and single-phase assurance, have provided fluid property information during a formation test, well test, or any other in situ well bore operation. The extreme conditions of the well bore (downhole) environment limit the sophistication of DFA measurement tools, and therefore limit the measurement of fluid properties to a small subset of those provided by a conventional (surface) laboratory analysis of a fluid sample.